Non-toxic, inexpensive synthetic drilling fluid

ABSTRACT

A non-toxic, inexpensive synthetic fluid for use in wellbore fluids (e.g., drilling fluids) is selected from the group consisting of (A) fluids having (I) a pour point greater than about −30° C. (−22° F.) and (II) a cetane index greater than 50, and comprising (i) at least about 95 weight percent hydrocarbons containing 11 or more carbon atoms, (ii) greater than 5 weight percent hydrocarbons containing 18 or more carbon atoms, (iii) at least about 50 weight percent isoparaffins, (iv) at least about 90 weight percent total paraffins, (v) about 1 or less weight percent naphthenics, (vi) less than 0.1 volume percent aromatics, and (vii) at least 2 hydrocarbons containing a consecutive number of carbon atoms, and (B) fluids comprising (i) at least about 95 weight percent hydrocarbons containing 10 or more carbon atoms and (ii) at least about 90 weight percent n-paraffins.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a division of application Ser. No. 08/580,112, filedJan. 29, 1996, now U.S. Pat. No. 5,958,845, which is acontinuation-in-part of application Ser. No. 08/494,441, filed Jul. 24,1995, now abandoned, which is a continuation-in-part of application Ser.No. 08/422,476, filed Apr. 17, 1995, now U.S. Pat. No. 5,635,457, whichapplications are incorporated herein in their entireties by reference.

BACKGROUND

The present invention relates to wellbore fluids (especially, syntheticfluid-based drilling fluids) and systems and processes for using them ina subterranean formation in oil and gas recovery operations.

While drilling fluids employing synthetic fluids (such aspolyalphaolefin- and ester-based drilling fluids) as the base fluid arecapable of achieving 96 hour LC₅₀ Mysid shrimp (Mysidopsis bahia)bioassay test results greater than 100,000 ppm, their commercial use hasbeen severely restricted because of the high cost of the syntheticfluids.

SUMMARY OF THE INVENTION

Accordingly, there is a need for a drilling fluid which employs aninexpensive, non-toxic synthetic fluid as the base fluid. The presentinvention satisfies this need by providing a drilling fluid comprising(a) at least one drilling fluid additive (e.g., an emulsifier, aviscosifier, a weighting agent, and an oil-wetting agent) and (b) aninexpensive, non-toxic base fluid. In one embodiment of the invention,the base fluid is a synthetic fluid having a pour point greater thanabout −30° C. (−22° F.) and comprising (i) at least about 95 weightpercent hydrocarbons containing 11 or more carbon atoms, (ii) greaterthan 5 weight percent hydrocarbons containing 18 or more carbon atoms,(iii) at least about 50 weight percent isoparaffins, (iv) at least about90 weight percent total paraffins, (v) at least 2 hydrocarbonscontaining a consecutive number of carbon atoms, (vi) less than about 1weight percent naphthenics, and (vii) less than about 0.1 volume percentaromatics. (This synthetic fluid is referred to hereinafter as the“isoparaffin synthetic fluid.”)

In another embodiment, the synthetic fluid comprises (1) at least about95 weight percent hydrocarbons containing 10 or more carbon atoms and(2) at least about 90 weight percent n-paraffins. (This synthetic fluidis referred to hereinafter as the “n-paraffin synthetic fluid.”) Then-paraffins usually also contain (i) less than about 10 weight percentnaphthenics and (ii) less than about 0.1 volume percent aromatics.

Typically, both the isoparaffin and n-paraffin synthetic fluids contain(i) less than about 1 weight percent sulfur, (ii) less than about 1weight percent nitrogen, and (iii) less than about 1 weight percentoxygenated compounds.

The cost of the synthetic fluids employed in the present invention iscomparable to that of diesel because the synthetic fluids are made byreacting inexpensive raw materials (e.g., H₂ and CO) on a massive scaledesigned to supply synthetic substitutes for gasoil and/or keroseneproduced at conventional oil refineries. In contrast, polyalphaolefinsand esters are made by polymerizing or reacting expensive raw materialson a small or moderate scale.

Because prior toxicity studies have shown that aromatics, sulfur,nitrogen, and oxygenated compounds can be toxic, the low orsubstantially non-existent concentrations of these materials in thesynthetic fluids used in the present invention is very desirable. Inaddition, the fluids employed in the present invention which are in factmade synthetically are also desirable in view of anticipatedenvironmental regulations which may restrict the off-shore discharge ofnon-aqueous-base drilling fluids to those drilling fluids using asynthetically produced base fluid.

A drilling system and a method for drilling a borehole are also providedby the invention. The drilling system comprises (a) at least on&subterranean formation, (b) a borehole penetrating a portion of at leastone of the subterranean formations, (c) a drill bit suspended in theborehole, and (d) the above drilling fluid located in the borehole andproximate the drill bit. The drilling method comprises the steps of (a)rotating a drill bit at the bottom of the borehole and (b) introducingthe aforesaid drilling fluid into the borehole (i) to pick up drillcuttings and (ii) to carry at least a portion of the drill cuttings outof the borehole.

DETAILED DESCRIPTION OF THE INVENTION

At least 95 weight percent of the isoparaffin synthetic drilling fluidis commonly composed of compounds containing 11 or more, and morecommonly 12 or more, carbon atoms. Also, the isoparaffin synthetic fluidconsists of greater than 5, typically greater than 10, more typicallygreater than 15, even more typically greater than 20, and most typicallygreater than 25, weight percent compounds containing more than 17 carbonatoms. In fact, compounds containing 18 or more carbon atoms canconstitute about 30, 35, 40, 45, or even 50 or more weight percent ofthe isoparaffin synthetic fluid. In addition, the isoparaffin syntheticfluid can contain isoparaffin, naphthenic, aromatic, sulfur, nitrogen,oxygenate, and total paraffin compounds in concentrations independentlyset forth in the following Table I.

TABLE I Isoparaffin Synthetic Fluid Composition Iso- Total Normalparaffin^(a), Naphthenic^(b), Aromatic^(c), Sulfur^(d), Nitrogen^(e),Oxygenate^(f), Paraffin^(g), Paraffin^(h), wt % wt % v % wt % wt % wt %wt % wt % ≧50 ≦1    ≦0.1   ≦1    ≦1    ≦1    ≧90   ≧5  ≧55 ≦0.5   ≦0.05 ≦0.5   ≦0.5   ≦0.5   ≧91   ≧10 ≧60 ≦0.1   ≦0.01  ≦0.1   ≦0.1   ≦0.1  ≧92   ≧15 ≦65 ≦0.05  ≦0.005  ≦0.05  ≦0.05  ≦0.05  ≧93   ≧20 ≦70 ≦0.01 ≦0.001  ≦0.01  ≦0.01  ≦0.01  ≧94   ≧25 ≦75 ≦0.005  ≦0.0005 ≦0.005 ≦0.005  ≦0.005  ≧95   ≧30 ≦80 ≦0.001  ≦0.0001 ≦0.001  ≦0.001  ≦0.001 ≧96   ≧35 ≦85 ≦0.0005 — ≦0.0005 ≦0.0005 ≦0.0005 ≧97   ≧40 ≦90 ≦0.0001≦0.0001 ≦0.0001 ≦0.0001 ≧98   ≦45 ≦95 ≧99   ≦50 ≧99.5 ^(a)As determinedby UMT 407-90. ^(b)As determined by UTM 407-90. ^(c)As determined byASTM D 5186. ^(d)As determined by ASTM D 2622. ^(e)As determined by ASTMD 4629. ^(f)As determined by UTM 484. ^(g)As determined by UMT 407-90.^(h)As determined by UMT 407-90.

The pour point of the isoparaffin synthetic fluid (as determined by ASTMD 97) is commonly greater than about −30° C. (−22° F.), more commonlygreater than about −25° C. (−13° F.), even more commonly greater thanabout −20° C. (−4° F.), and most commonly greater than about −15° C. (5°F.). Usually, the pour point of the isoparaffin synthetic fluid is lessthan about 6° C. (43° F.), preferably less than about 3° C. (37° F.),more preferably less than about 0° C. (32° F.), and most preferably lessthan about −3° C. (27° F.).

The flash point of the isoparaffin synthetic fluid (as determined by theCleveland Open Cup method) is at least about 65.6° C. (150° F.),typically at least about 71.1° C. (160° F.), more typically about 76.7°C. (170° F.), even more typically at least about 82.2° C. (180° F.), andmost typically at least about 85° C. (185° F.). Usually, the flash pointof the isoparaffin synthetic fluid is less than about 121.1° C. (250°F.), lore typically about 118.3° C. (245° F.) or less, even moretypically about 115.6° C. (240° F.) or less, and most about 112.8° C.(235° F.) or less.

As measured by ASTM D 93, the flash point of the isoparaffin syntheticfluid is at least about 65.6° C. (150° F.), typically at least about71.1° C. (160° F.), more typically about 76.7° C. (170° F.), even moretypically at least about 82.2° C. (180° F.), and most typically at leastabout 85° C. (185° F.), but usually less than about 115° C. (239° F.),more typically about 110° C. (230° F.) or less, even more typicallyabout 105° C. (221° F.) or less, and most about 100° C. (212° F.) orless.

The isoparaffin synthetic fluid frequently has an initial boiling point(as determined by ASTM D 86) of at least about 160° C. (320° F.), morefrequently at least about 165° C. (329° F.), even more frequently atleast about 170° C. (338° F.), and most frequently at least about 175°C. (347° F.) or even at least about 180° C. (356° F.). In addition, theisoparaffin synthetic fluid commonly has a final boiling point (asdetermined by ASTN D 86) of at least about 340° C. (644° F.), morecommonly at least about 345° C. (653° F.), even more commonly at leastabout 350° C. (662° F.), and most commonly at least about 351° C.(663.8° F.). Furthermore, the final boiling point of the isoparaffinsynthetic fluid is typically about 375° C. (707° F.) or less, moretypically about 370° C. (698° F.) or less, even more typically about365° C. (689° F.) or less, and most typically about 360° C. (680° F.) orless.

The viscosity of the isoparaffin synthetic fluid at 40° C. (104° F.) (asmeasured by ASTM D 445) is ordinarily between about 1 to about 10centistokes (cst). Preferably, the viscosity of the isoparaffinsynthetic fluid at 40° C. (104° F.) is less than about 6, morepreferably less than about 5, even more preferably less than about 4.5and lost preferably less than about 4, cst.

At 15° C., the isoparaffin synthetic fluids commonly have an API gravitygreater than about 40°, more commonly greater than about 42°, even morecommonly greater than about 44°, and most commonly greater than about46°.

The cetane index (as determined by ASTK D 976) is generally greater thanabout 60, preferably greater than about 62, more preferably greater thanabout 64, even more preferably greater than about 66, and mostpreferably greater than about 68. In fact, the cetane index isfrequently at least about 70, 71, 73, 74, 75, 76, about 77 or more.

An isoparaffin synthetic fluid commercially available from KDS(Nalaysia)typically has the properties set forth in the following Table II.

TABLE II Typical Properties of MDS (Malaysia) Isoparaffin SyntheticFluid Value Property Typical Max Min Test Method Density at 15° C.,kg/m³ 738 790 ASTM D 1298 ASTM Color 0 2.0 ASTM D 1500 DistillationRange, ° C. ASTM D 86 IBP 201 175  5% 219 50% 271 90% 350 95% 353 FBP358 360 Sulphur, ppm 0 500 ASTM D 1266 Cetane Index 75 70 ASTM D 976Flash Point, ° C. 88 68 ASTM D 93 Pour Point, ° C. −7 ASTM D 97 CloudPoint, ° C. −2 ASTM D 2500 CFPP, ° C. −3 IP 309 Kinematic Viscosity 4.3ASTM D 445 at 40° C., cSt Aromatics, % v <0.1 ASTM D 5186 API Gravity at15° C., ° 48.75

An interesting characteristic of the isoparaffin synthetic fluiddescribed in above Table II is that mono- and poly-methyl isomerstypically constitute at least about 90, more typically at least about92, even more typically at least about 94, and most typically at leastabout 96, weight percent of the C11 or less isoparaffinic content of theisoparaffin synthetic fluid. In fact, the mono- and poly-methyl isomersof isoparaffins containing 11 or less carbon atoms can constitute 97,98, or oven 99, weight percent of the isoparaffin hydrocarbons having upto 11 carbon atoms. In other words, for the isoparaffin synthetic fluidreported in Table II, isoparaffins whose branched moieties contain morethan one carbon atom (e.g., have an ethyl, propyl, butyl, or largersubstituent group) constitute a negligible portion of the total amountof isoparaffins containing 11 or less carbon atoms.

Two other isoparaffin synthetic fluids commercially available from MDS(Malaysia) typically have the properties set forth in the followingTable III.

TABLE III Typical Properties of MDS (Malaysia) Isoparaffin SyntheticFluid Value Property Fluid A Fluid B Test Method Density at 15° C.,kg/m³ 738.8 784.2 ASTM D 1298 ASTM Color <0.5 <0.5 ASTM D 1500Distillation Ranqe, ° C. ASTM D 86 IBP 207.1 217.4 FBP 351.4 353.8Sulphur, ppm >50 >50 ASTM D 1266 Cetane Index 77.5 75.5 ASTM D 976-91Flash Point, ° C. 86 97 ASTM D 93-90 Pour Point, ° C. <0 <0 ASTM D 97-87Kinematic Viscosity 3.4 3.5 ASTM D 445 at 40° C., cSt Aromatics, % v<0.1 <0.1 UV method

Another isoparaffin synthetic fluid, which is commercially availablefrom Sasol, has the properties shown in the following Table IV.

TABLE IV Typical Sasol Brand Isoparaffin Synthetic Fluid PropertiesProperty Value Test Method Density at 20° C., kg/l 0.778-0.785 ASTM D1298 Color, Saybolt +30 ASTM D 156 Distillation Ranqe at 101.3 KpalsASTM D 1078 IBP, ° C. 200 min. FBP, ° C. 250 max. Sulphur, % mass <0.01ASTM D 2622 Flash Point 77 IP 170 (closed cup at 101.3 kPa), ° C.Kinematic Viscosity at 40° C. 1.6-2.1 ASTM D 445 Aromatics, % mass 1max. GC Water, % mass 0.01 ASTM D 1744 Acidity, mgKOH/G 0.01 ASTM D 3242Ash, % mass 0.01 ASTM D 482 Ionol content, mg/kg 900-1100 GC

When the isoparaffin synthetic fluids are employed as the base fluid ina drilling mud, the base oil generally contains less than 1, preferablyless than about 0.9, more preferably less than 0.8, even more preferablyless than about 0.7, and most preferably less than about 0.6, weightpercent polar activator (e.g., polar ether alcohols). In fact, theconcentration of polar activators in the base fluid is commonly lessthan about 0.5, more commonly less than about 0.4, even more commonlyless than about 0.3, and most commonly less than about 0.2, weightpercent. In addition, the base fluid can contain less than about 0.1,0.05, 0.01, 0.05, 0.001, weight percent polar activator or even betotally devoid of any polar activator. Furthermore, when the base fluidis the isoparaffin synthetic fluid, the entire drilling mud usuallycontains less than 1, preferably less than about 0.75, sore preferablyless than 0.5, even more preferably less than about 0.25, and mostpreferably less than about 0.1, weight percent polar activator. In fact,in such instances the drilling mud can contain less than about 0.05,0.01, 0.005, 0.001, weight percent polar activator or be entirely devoidof any polar activator.

With respect to the n-paraffin synthetic fluid, at least 95 weightpercent of the n-paraffin synthetic drilling fluid is generally composedof compounds containing 10 or more carbon atoms. Typically, at least 95weight percent of the n-paraffin synthetic drilling fluid is composed ofcompounds containing 11 or more, more typically 12 or lore, even moretypically 13 or more, and most typically 14 or more carbon atoms.Usually, the n-paraffin synthetic fluid contains less than about 5, morecommonly less than 3, even more commonly less than about 2, and mostcommonly less than about 1, weight percent of compounds containing 18 ormore carbon atoms. In addition, the n-paraffin synthetic fluid cancontain n-paraffin, iso-paraffin, naphthenic, aromatic, sulfur,nitrogen, and oxygenate compounds in concentrations independently listedin the following Table V.

TABLE V N-paraffin Synthetic Fluid Composition N-paraffin^(a),Naphthenic^(b), Aromatic^(c), Sulfur^(d), Nitrogen^(e), Oxygenates^(f),Isoparaffins^(g), wt % wt % v % wt % wt % wt % wt % ≧90 ≦10    ≦0.1  ≦1    ≦1    ≦1    ≦10 ≧91 ≦5     ≦0.05  ≦0.5   ≦0.5   ≦0.5   ≦9  ≧92≦1     ≦0.01  ≦0.1   ≦0.1   ≦0.1   ≦8  ≧93 ≦0.5   ≦0.005  ≦0.05  ≦0.05 ≦0.05  ≦7  ≧94 ≦0.1   ≦0.001  ≦0.01  ≦0.01  ≦0.01  ≦6  ≧95 ≦0.05  ≦0.0005 ≦0.005  ≦0.005  ≦0.005  ≦5  ≧96 ≦0.01   ≦0.0001 ≦0.001  ≦0.001 ≦0.001  ≧4  ≧97 ≦0.005  — ≦0.0005 ≦0.0005 ≦0.0005 ≧3  ≦0.001  ≦0.0001≦0.0001 ≦0.0001 ≧2  ≦0.0005  ≧1  ≦0.0001  ^(a)As determined by UMT407-90. ^(b)As determined by UTM 407-90. ^(c)As determined by ASTM D5186. ^(d)As determined by ASTM D 2622. ^(e)As determined by ASTM D4629. ^(f)As determined by UTM 484. ^(g)As determined by UMT 407-90.

The pour point of the n-paraffin synthetic fluid (as determined by ASTMD 97) is commonly greater than about −30° C. (−22° F.) and more commonlygreater than about −23° C. (−13°F.). Frequently, the pour point of then-paraffin synthetic fluid is less than about 10° C. (50° F.), morefrequently less than about 9° C. (48.2° C.), even more frequently lessthan about 8° C. (46.4° F.), and most frequently less than about 7° C.(44.6° F.).

The flash point of the n-paraffin synthetic fluid (as determined by ASTMD 93) is typically at least about 65° C. (149° F.), more typically atleast about 70° C. (158° F.), even more typically at least about 73° C.(167° F.), and most typically at least about 80° C. (176° F.). Then-paraffin synthetic fluids can have even higher flash points, such asat least about 85° C. (185° F.), 90° C. (194° F.), 95° C. (203° F.), orat least about 100° C. (212° F.) or higher.

The n-paraffin synthetic fluid frequently has an initial boiling point(as determined by ASTK D 86) of at least about 190° C. (374° F.), morefrequently at least about 200° C. (392° F.), even more frequently atleast about 210° C. (410° F.), and most frequently at least about 220°C. (428° F.). Even higher initial boiling points, such as about 230° C.(446° F.), 240° (464° F.), or 250° C. (482° F.) or more, are not unusualfor the n-paraffin synthetic fluids.

The viscosity of the n-paraffin synthetic fluid at 40° C. (104° F.) (asmeasured by ASTH D 445) is ordinarily between about 1 to about 10 cot.Preferably, the viscosity of the n-paraffin synthetic fluid at 40° C.(104° F.) is less than about 5, more preferably less than about 4, evenmore preferably less than about 3, and most preferably less than about2, cst.

At 15° C., the n-paraffin synthetic fluids commonly have an API gravitygreater than about 45°, more commonly greater than about 50°, even morecommonly greater than about 50.5°, and most commonly greater than about51°.

Typical properties for some commercially available n-paraffin syntheticfluids are shown in the following Tables VI and VII.

TABLE VI Typical Properties of MDS (Malaysia) Brand N-paraffin SyntheticFluids Sarapar Sarapar Property 103 147 Test Method Saybolt Color +30+30 ASTM D 156 Bromine Index, mgBr/100 g 8 6 ASTM D 2710 Sulphur, ppm 00 ASTM D 5120 Carbon Distribution, % mass nC9 0 0 nC10 9 0 nC11 30 0nC12 29 0 nC13 27 4 nC14 1 25 nC15 0 24 nC16 0 22 nC17 0 16 nC18 0 4nC19 0 0 n-Paraffin content, mass 96 95 Average Molecular Mass 167 213Density at 15° C., kg/M³ 750 775 ASTM D 4052 Distillation Ranqe, ° C.ASTM D 86 IBP 190 250 FBP 230 280 Flash Point, ° C. 75 110 ASTM D 93Pour Point, ° C. −20 5 ASTM D 97 Viscosity at 25° C., mm/s 1.7 3.3 ASTMD 445 API Gravity at 15° C., ° 57.17 51.08

TABLE VII Typical Properties Of Sasol Brand N-paraffin Synthetic FluidsParaffins Light Heavy Property Specification Typical SpecificationTypical Test Method n-Paraffins, % mass 92 min. 93 92 min. 93 Sasol11.28/83 Aromatics, % mass 0.5 max. <0.1 0.5 max. <0.1 Sasol 5.107/92Bromine Index, mg Br/100 g 20 max. <10 20 max. <10 ASTM D 2710-89Sulphur, ppm 5 max. <1 5 max. <1 ANTEK 1.211/92 Acidity, mg KOH/g 0.02max. <0.01 0.02 max. <0.01 ASTM D 3242 Ash, % mass 0.03 max. <0.01 0.03max. <0.01 ASTM D 482 Saybolt Color +30 min. +30 +25 min +30 ASTM D 156Carbon Distribution, % mass Sasol 11.28/83 C9 and lighter 0.5 max. <0.1C10 4-10 5 C11 30-38 35 C12 29-37 32 C13 23-30 28 C14 and heavier 0.5max. 0.2 C13 and lighter 0.5 max. 3.5 C14 and heavier 0.5 max. 0.2 C13and lighter 0.5 max. 3.5 C14-C17 95 min. 96 C18 and heavier 1 max. 0.3Boiling Range, ° C. 192-226 254-287 Pour Point, ° C. <0 3 Flash Point, °C. 70 114 Average Molecular Mass 163 219 Density at 25° C., kg/l 0.744API Gravity at 25° C., ° 58.43 Viscosity at 40° C., cst 2.4

The synthetic fluids of the present invention are prepared by theFischer-Tropsch process and various modifications thereof (especiallythe Shell Middle Distillate Synthesis process). See, for example, Sie atal., Catalysis Today, 8:371-394 (1991); van der Burgt et al., PetroleumReview, pages 204-209 (April 1990); Oil & Gas Journal, pages 74-76 (Feb.17, 1986); Eilers et al., Catalysis Letters, pages 253-270 (1990);Bartholomew, Catalysis Letters, pages 303-316 (1990); Gregor, CatalysisLetters, pages 317-332 (1990); Dry, Journal of Organometallic Chemistry,372:117-127 (1989); Dry, Applied Industrial Catalysis, 2:167-213 (1983);and Dry, Hydrocarbon Processing, pages 121-124 (August 1982), thesepublications being incorporated herein in their entireties by reference.In general, the Fischer-Tropsch process entails reacting carbon monoxideand hydrogen over a catalyst (e.g., iron, ruthenium, or cobalt) toproduce products which, in the absence of secondary transformations, arehighly linear. When desired, some or all of the linear products aresubjected to a conversion process (such as the Shell Middle DistillateSynthesis Process) where (a) olefins present in the Fischer-Tropschproduct are hydrogenated, (b) small amounts of oxygen-containingcompounds, mainly primary alcohols, are removed, (c) the Fischer-Tropschproduct is hydroisomerized, and (d) the n-paraffins are hydrocracked toisoparaffins of a desired chain length and/or boiling range.

Due to the manner in which they are synthesized, the synthetic fluidsare composed of hydrocarbons containing a consecutive number of carbonatoms (i.e., a mixture of hydrocarbons where the carbon atom content ofthe individual hydrocarbons is C_(n), C_(n+1), C_(n+2), C_(n+3), etc.and n is a whole number.) Generally, the synthetic fluids are composedof at least 2, more commonly at least 3, even more commonly at least 4,and most commonly at least 5 hydrocarbons containing a consecutivenumber of carbon atoms. In fact, some synthetic fluids contain at least6, 7, 8, 9, or 10 or more hydrocarbons having a consecutive number ofcarbon atoms.

The synthetic fluids are commercially available from Sasol in SouthAfrica and Shell Middle Distillate in Malaysia and are preferably thefraction which has a boiling range similar to gasoils and/or kerosenesproduced at conventional petroleum refineries.

Optionally, one or more pour point depressants are employed in thesynthetic fluids of the present invention to lower their pour point.Typical pour point depressants include, but are not limited to, ethylenecopolymers, isobutylane polymers, polyaklylnaphthalenes, wax-aromaticcondensation products (e.g., wax-naphthalene condensation products,phenol-wax condensation products), polyalkylphenoleosters,polyalkylmethacrylates, polymethacrylates, polyalkylated condensedaromatics, alkylaromatic polymers, iminodiimides, and polyalkylstyrene.(The molecular weights for polyaklylnaphthalenes, polyalkylphenolesters,and polyalkylmethacrylates range from about 2,000 to about 10,000.)Because they are non-toxic, ethylene copolymers and isobutylene polymersare the preferred pour point depressants.

Up to about 1 weight percent pour point depressant is employed. (As usedin the specification and claims, the weight percent of the pour pointdepressant is based upon the weight of the synthetic fluid, i.e., it isthe weight of the pour point depressant divided by the weight of thesynthetic fluid, the quotient being multiplied by 100%.) Preferably, thepour point depressant is employed in a concentration of 0.005 to about0.5, more preferably about 0.01 to about 0.4, and most preferably about0.02 to about 0.3, weight percent.

When employed, the pour point depressant is preferably mixed with thesynthetic fluid and the resulting composition is then combined with anyadditional additives as described below.

One or more surfactants (e.g., emulsifiers, wetting agents),viscosifiers, weighting agents, fluid loss control agents, and shaleinhibiting salts are also optionally used in the drilling fluid of thepresent invention. (As used in the specification and claims, the term“surfactant” means a substance that, when present at low concentrationin a system, has the property of adsorbing onto the surfaces orinterfaces of the system and of altering to a marked degree the surfaceor interfacial free energies of those surfaces (or interfaces). As usedin the foregoing definition of surfactant, the term “interface”indicates a boundary between any two immiscible phases and the term“surface” denotes an interface where one phase is a gas, usually air.)Because the drilling fluids of the present invention are intended to benon-toxic, these optional ingredients, like the synthetic fluid, arepreferably also non-toxic.

Exemplary emulsifiers include, but are not limited to, fatty acids,soaps of fatty acids, and fatty acid derivatives including amido-amines,polyamides, polyamines, esters (such as sorbitan monoleatepolyethoxylate, sorbitan dioleate polyethoxylate), imidaxolines, andalcohols.

Typical wetting agents include, but are not limited to, lecithin, fattyacids, crude tall oil, oxidized crude tall oil, organic phosphateesters, modified imidazolines, modified amidoamines, alkyl aromaticsulfates, alkyl aromatic sulfonates, and organic esters of polyhydricalcohols.

Exemplary weighting agents include, but are not limited to barite, ironoxide, gelana, siderite, and calcium carbonate.

Common shale inhibiting salts are alkali metal and alkaline-earth metalsalts. Calcium chloride and sodium chloride are the preferred shaleinhibiting salts.

Exemplary viscosifiers include, but are not limited to, organophilicclays (e.g., hectorite, bentonite, and attapulgite), non-organophilicclays (e.g., montmorillonite (bentonite), hectorite, saponite,attapulgite, and illite), oil soluble polymers, polyamide resins, andpolycarboxylic acids and soaps. (As used in the specification andclaims, the term “non-organophilic clay” means a clay which has not beenamine-treated to convert the clay from water-yielding to oil-yielding.)

Illustrative fluid loss control agents include, but are not limited to,asphaltics (e.g., asphaltenes and sulfonated asphaltenes), amine treatedlignite, and gilsonite. For drilling fluids intended for use in hightemperature environments (e.g., where the bottom hole temperatureexceeds about 204.4° C. (400° F.)), the fluid loss control agent ispreferably a polymeric fluid loss control agent. Exemplary polymericfluid loss control agents include, but are not limited to, polystyrene,polybutadiene, polyethylene, polypropylene, polybutylene, polyisoprene,natural rubber, butyl rubber, polymers consisting of at least twomonomers selected from the group consisting of styrene, butadiene,isoprene, and vinyl carboxylic acid. Individual or mixtures of polymericfluid loss control agents can be used in the drilling fluid of thisinvention.

For drilling fluids intended for use in high temperature environments(e.g., where the bottom hole temperature exceeds about 204.4° C. (400°F.)), it is desirable to use the synthetic fluid as the bass material inconjunction with the formulations and materials disclosed in U.S. patentapplications Ser. No. 07/786,034 and Ser. No. 08/268,801, whichapplications are incorporated herein in their entireties by reference.

General drilling fluid formulations are set forth in the following TableVIII:

TABLE VIII Ingredient Typical More Typical Synthetic fluid, volume %^(a)25-85 40-60 Surfactant (active), ppb^(b) 0.5-40   3-25 kg/m³ 2.86-57.22.86-28.6 Water, volume %^(a) up to 45    1-20 Weighting agent, ppb upto 700   150-600 kg/m³ up to 2002   429-1716 Polymer viscosifier, ppb0.05-15   0.1-6   kg/m³ 0.143-42.9  0.286-17.16 Organophilic clay, ppbup to 15   0.1-6   kg/m³ up to 42.9  0.286-17.16 Shale inhibiting salt,ppb up to 60    5-30 kg/m³ up to 171.6  143-85.8 Lime^(c), ppb up to30    1-20 kg/m³ up to 85.8  2.86-57.2 Fluid loss control agent, ppb upto 30    2-20 kg/m³ up to 85.8  5.72-57.2 ^(a)Volume percent is based onthe total volume of the drilling fluid. ^(b)The pounds per barrel (ppb)is based upon the final composition of the drilling fluid. ^(c)As usedin the specification and claims, the term “lime” means quicklime (CaO),quicklime precursors, and hydrated quicklime (e.g., slaked lime(Ca(OH)₂)).

The properties (e.g., synthetic fluid to water ratio, density, etc.) ofthe drilling fluids of the invention can be adjusted to suit anydrilling operation. For example, the drilling fluid is usuallyformulated to have a volumetric ratio of synthetic fluid to water ofabout 100:0 to about 40:60 and a density of about 0.9 kg/l (7.5 poundsper gallon (ppg)) to about 2.4 kg/l (20 ppg). More commonly, the densityof the drilling fluid is about 1.1 kg/l (9 ppg) to about 2.3 kg/l (19ppg).

The drilling fluids are preferably prepared by mixing the constituentingredients in the following order: (a) synthetic fluid, (b) emulsifier,(c) line, (d) fluid loss control agent, (e) an aqueous solutioncomprising water and the shale inhibiting salt, (f) organophilic clay(when employed), (g) oil wetting agent, (h) weighting agent, (i)non-sulfonated polymer, (j) sulfonated polymer (when employed), and (k)non-organophilic clay (when employed).

EXAMPLES

The following examples (which are intended to illustrate and not limitthe invention defined by the claims) demonstrate the preparation ofexemplary drilling fluids within the scope of the present invention(Examples 1-7), show the results obtained from an analysis of anisoparaffin synthetic fluid sample (Example 8), document initial andaged rheological properties of a drilling fluid which employs theisoparaffin synthetic fluid sample as the base fluid (Example 9), andcompare the toxicity of two drilling fluids which solely differ in thatthe base fluid of one is the isoparaffin synthetic fluid sample and thebase fluid of the other is the diner of 1-decene (a commercially used,non-toxic base fluid).

Examples 1-6

Preparation of Drilling Fluids

Six drilling fluids (3 lab barrels per drilling fluid formulation, witheach lab barrel containing about 350 ml) having a density of about 2.16kg/l (about 18 ppg) and within the scope of the present invention areformulated by sequentially adding ingredients in the order set forth inTable A. After the addition of each ingredient, the resultingcomposition is mixed for the indicated mixing time prior to adding asubsequent ingredient to the composition.

TABLE A Examples Mixing Time, Component 1 2 3 4 5 6 minutes Syntheticfluid, ml 164.5 164.5 164.5 164.5 164.5 164.5 Primary emulsifier, ml 8.58.5 8.5 8.5 8.5 8.5 Lime, g 8.0 8.0 8.0 8.0 8.0 8.0 Fluid loss controlagent, g 10.0 10.0 10.0 10.0 10.0 10.0 20 Brine solution 10 CaCl₂, g12.1 12.1 12.1 12.1 12.1 12.1 Water, ml 23.8 23.8 23.8 23.8 23.8 23.8Organophilic clay, g 1.0 2.0 3.0 2.0 2.0 1.0 20 Oil wetting agent, ml6.0 6.0 6.0 6.0 6.0 6.0 10 Weighting Agent, g 572 572 572 572 572 572 20Styrene-butadiene polymer, g 0 0 0 0 0 2.0 10 Polystyrene, g 3.0 3.0 3.04.0 2.0 3.0 10 Bentonite, g 3.0 3.0 3.0 2.0 4.0 3.0 35

Example 7

Preparation Of Drilling Fluid

An invert emulsion drilling fluid is prepared by (a) initially agitatingabout 240 ml of a synthetic fluid for about 1 minute using a blender and(b) then sequentially adding the following ingredients (with continuousmixing for about one minute after the addition of each material): (i)about 6 g of a primary emulsifier; (ii) about 8 g of lime (calciumhydroxide); and (iii) about 4 g of a fluid-loss preventing agent.

Subsequently, about 39 ml of fresh water is added to the above mixtureand the resulting composition is mixed for about ten minutes. Then,about 11 g of an amine-treated bentonite is added and the resultingmixture is agitated for about 15 minutes.

Thereafter, the following materials are added in sequence, with about 5minutes of mixing after the addition of each of the materials: (i) about2 g of a secondary emulsifier; (ii) about 210 g of powdered barite (anon-toxic weighting agent); (iii) about 24 g of calcium chloridedihydrate (to provide salinity to the water phase without water wettingthe barite); and (iv) about 20 g of a powdered clay (composed of about35 weight percent smectite and about 65 weight percent kaolinite) tosimulate drilled formation particles.

Example 8

Analysis of Isoparaffin Synthetic Fluid Sample

Analytical results obtained from the analysis of an isoparaffinsynthetic fluid sample from shell Malaysia by gas chromatography arereported in the following Tables B-D.

TABLE B Carbon Number Distribution Results Carbon Number Weight PercentOff 8 0.31 9 0.41 10 0.84 11 1.86 12 4.61 13 6.22 14 7.13 15 8.33 168.38 17 9.43 18 11.04 19 10.95 20 10.39 21 8.23 22 5.95 23 3.43 24 1.5125 0.64 >25 0.34

TABLE C Paraffin Distribution Results Analytical Data Calculated ResultsCarbon n-Paraffin Iso-Paraffin Ratio of Content Wt. % Wt. % Iso/nParaffin 10 0.60 0.24 0.40 11 1.55 0.31 0.20 12 2.60 2.01 0.773 13 2.833.39 1.198 14 5.22 1.91 0.366 15 4.70 3.63 0.77 16 4.30 4.01 0.949 174.69 4.74 1.01 18 4.52 6.52 1.44 19 3.33 7.62 2.29 20 2.25 8.14 3.62 211.53 6.70 5.17 22 0.89 5.06 5.68 23 0.39 3.04 7.79 24 0.12 1.39 11.58 250.03 0.61 20.33 26 0.01 0.33 33 27 0.00 28 0.00 Total 39.53 

Based upon the results listed in Table C, the iso-paraffin/n-paraffinratio of the isoparaffin synthetic fluid sample for compounds containingfrom 17 to 20 carbon atoms follows the equationy=(x-16)^((0.53+0.2(x-18))), where x is the carbon number and y is theiso-paraffin/n-paraffin ratio. In addition, for compounds containing 21to 25 carbon atoms, the iso-paraffin/n-paraffin ratio of the isoparaffinsynthetic fluid sample follows the equationy=(x-21)^((1.48+0.25(x-23))), where x and y are as defined above. Theforegoing equations are generally accurate within ±1 unit and evenwithin ±0.5 unit.

TABLE D Percent Off To Temperature Results Temperature Temperature Wt %Off ° C. ° F. V % Off ° C. ° F. 0.5 150.0 302 0.5 145.6 294 5.0 207.8406 5.0 205.6 402 10.0 222.8 433 10.0 221.1 430 15.0 237.8 460 15.0236.7 458 20.0 253.9 489 20.0 252.8 487 25.0 260.6 501 25.0 257.8 49630.0 272.2 522 30.0 271.7 521 35.0 281.7 539 35.0 280.0 536 40.0 289.4553 40.0 288.9 552 45.0 298.9 570 45.0 297.2 567 50.0 304.4 580 50.0304.4 580 55.0 311.7 593 55.0 310.6 591 60.0 318.3 605 60.0 317.8 60465.0 323.9 615 65.0 322.8 613 70.0 331.7 629 70.0 330.6 627 75.0 337.2639 75.0 335.6 636 80.0 345.0 653 80.0 344.4 652 85.0 351.7 665 85.0351.1 664 90.0 360.0 680 90.0 359.4 679 95.0 371.7 701 95.0 371.1 70099.5 399.4 751 99.5 398.9 750

In addition, the gas chromatography analysis (both mass spectrometry andflame ionization detector (FID)) did not detect the presence of eitheraromatic or naphthenic compounds.

Example 9

Preparation And Testing of Isoparaffin Synthetic Fluid-ContainingDrilling Fluid

Each of two substantially identical samples of an oil-base drillingfluid within the scope of the present invention was formulated asfollows. (The isoparaffin synthetic fluid sample analyzed in Example 8was employed as the synthetic fluid.) Ingredients were sequentiallyadded in the order sot forth below in Table E. After the addition ofeach ingredient, the resulting composition was mixed for the indicatedmixing time prior to adding a subsequent ingredient to the composition.

TABLE E Mixing Time, Component minutes Synthetic Fluid, ml 209 Imvitonebrand organophilic clay, g 7.0 30 Novamul brand emulsifier, ml 10.0Novamod brand rheology modifier, g 2.0 10 Lime, g 10.0 10 Brine solution30 CaCl₂, g 26.3 Water, ml 51.3 Versatrol I brand fluid loss 10.0 15control agent, g Barite, g 269 30

One sample was used to check the initial rheological properties, and theother sample was used to test the aged rheological properties. Theage-tested sample was placed into an aging bomb in the presence of about790.8 kpascal (100 psi) nitrogen and rolled at about 176.7° C. (350°F.). After aging, the rheological properties of the age-tested samplewere checked. Unless otherwise noted below in Table F, both the initialand age-tested rheological properties were measured at about at 48.90°C. (120° F.) according to procedures described in RecommendedPractice—Standard Procedure for Field Testing Drilling Fluids, APIRecommended Practice 13B-2 (RP 13B-2), Second Edition, Dec. 1, 1991,American Petroleum Institute, Washington, D.C. (hereinafter referred toas “API”), API being incorporated herein in its entirety by reference.The measured results are set forth in Table F.

TABLE F Drilling Fluid Rheological Properties Property Initial Aged Dialreading^(a), 600 rpm 103 106 300 rpm 74 61 200 rpm 59 48 100 rpm 42 29 6 rpm 20 8  3 rpm 18 7 Gel Strength^(b), 10 sec, lb/100 ft² 19 7 kg/10m² 9.3 3.4 10 min, lb/100 ft² 23 37 kg/10 m² 11.2 18.0 PV^(c), cp 29 45N-sec/m² (10³) 29 45 YP^(d), lb/100 ft² 45 16 kg/10 m² 22.0 7.8 HTHPfluid loss^(e), ml 2.8 2.8 ES^(f), volts 814 593 API fluid loss, ml 1.50 Cake 0 0 ^(a)Dial readings were obtained using a 115-volt motor drivenviscometer and measured according to the procedure # described in API,pages 9-10, sections 2.4 to 2.5. ^(b)Gel strength for 10 seconds and 10minutes was determined in accordance with the procedure discussed inAPI, # page 10, section 2.5, paragraphs f and g, respectively. ^(c)PVwas determined in accordance with the procedure and calculationsdiscussed in API, page 10, sections # 2.5 to 2.6. ^(d)YP was determinedin accordance with the procedure and calculations discussed in API, page10, sections # 2.5 to 2.6. ^(e)HTHP denotes“high-temperature/high-pressure test” and was determined in accordancewith the # procedure discussed in API, pages 13-14, section 3. ^(f)“ES”denotes “electrical stability” and was measured in accordance with theprocedure # discussed in API, pages 21-22, section 6.

Example 10

Toxicity Study

With one modification, another drilling fluid was prepared in accordancewith the protocol set forth in preceding Example 9 using the isoparaffinsynthetic fluid analyzed in Example 9 as the synthetic fluid. The solemodification consisted of using about ten times the amount of eachingredient in formulating the drilling fluid. The drilling fluid wassubjected to the 96 hour LC₅₀ Mysid shrimp (Mysidopsis bahia) bioassaytest by an independent laboratory and achieved a score of about 396×10³.

Example 11

Comparative Toxicity Study

With two modifications, another drilling fluid was prepared inaccordance with the protocol set forth above in Example 9. Onemodification entailed using the diner of 1-decene (the base syntheticfluid of Novadril brand non-toxic drilling fluid) as the syntheticfluid, and the other modification consisted of using about ten times theamount of each ingredient in formulating the drilling fluid. Thedrilling fluid was subjected to the 96 hour LC₅₀ Mysid shrimp(Mysidopois bahia) bioassay test by the same independent laboratoryemployed in Example 10 and achieved a score of about 207.6×10³.

Since a higher numerical result obtained by the 96 hour LC₅₀ Mysidshrimp (Mysidopois bahia) bioassay test is indicative of lower toxicityof the material test, comparative Examples 10-11 indicate that asynthetic fluid within the &cope of the present invention issubstantially less toxic than the commercially used Novadril brandsynthetic fluid. The reason for this is that the number obtain by theexemplary synthetic fluid-containing drilling fluid is roughly about 1.9times greater than that obtained by the Novadril-containing drillingfluid. In fact, the results documented in comparative Examples 10-11 arequite surprising and unexpected because conventional wisdom in thedrilling fluids industry considers toxicity to increase with decreasingcarbon content and the tested synthetic fluid within the scope of thepresent invention has a significantly higher concentration ofhydrocarbons containing less than 20 carbon atoms than present in theNovadril brand synthetic fluid.

Example 12

Additional Analysis of Isoparaffin Synthetic Fluid Samples

Analytical results obtained from the analysis of two additionalisoparaffin synthetic fluid samples from Shell Malaysia by gaschromatography are reported in the following Table G.

TABLE G Carbon Number Distribution Results Weight Percent Off CarbonTotal Organics N-Alkanes Only^(a) Number Sample A Sample B Sample ASample B ≦6 0.02 0.05  0.013  0.023 7 0.07 0.14  0.050  0.096 8 0.230.39  0.161 0.25 9 0.59 0.78  0.354 0.42 10 0.93 1.21 0.55 0.66 11 1.422.15 0.67 1.05 12 5.17 7.57 1.96 3.33 13 7.49 10.21  2.17 3.17 14 9.2210.16  3.60 2.74 15 9.0O 8.99 3.87 2.43 16 9.26 7.84 4.35 2.19 17 9.308.59 4.46 3.01 18 13.45  11.21  5.78 4.37 19 11.53  9.83 4.61 3.64 207.57 7.60 2.95 2.51 21 5.94 5.32 2.32 1.76 22 4.50 4.06 1.39 1.05 232.42 2.33 0.65 0.51 24 1.00 0.94 0.27 0.19 25 0.42 0.31  0.076 0.037 >25 0.49 0.30 Total 100.02  99.98  140.254 33.436 FP^(b), ° C.(°F.) 110(231) 106(224) ^(a)“(N-Alkanes/TO) 100%” denotes, for a givencarbon number, the weight percent off of n-alkanes # divided by theweight percent off of total organics, the quotient being multiplied by100%. ^(b)“FP” denotes flash point as determined by Cleveland Open Cupmethod.

Although the present invention has been described in detail withreference to some preferred versions, other versions are possible. Forexample, the synthetic fluid can also be employed as the base liquidcomponent in other wellbore fluids. (As used in the specification andclaims, the term “wellbore fluid” means a fluid used while conductingpay zone drilling, underreaming, drilling in, plugging back, sandcontrol, perforating, gravel packing, chemical treatment, hydraulicfracturing, cleanout, well killing, tubing and hardware replacement, andzone selective operations (e.g., well completion operations) as well asa fluid employed as a packer fluid or as a spotting fluid.) In additionto the base liquid, the wellbore fluids contain one or more additionalingredients such as proppants suitable for use in hydraulicallyfracturing subterranean formations, particulate agents suitable for usein forming a gravel pack, viscosifiers, organophilic clays, and fluidloss control agents.

Common proppants suitable for use in hydraulic fracturing procedures arequartz sand grains, tempered glass beads, sintered bauxite, resin coatedsand, aluminum pellets, and nylon pellets. Generally, the proppants areemployed in the wellbore fluids intended for use as hydraulic fracturingfluids and are used in concentrations of roughly about 1 to about 10pounds per gallon of the wellbore fluid. The proppant size is typicallysmaller than about 2 mesh on the U.S. Sieve Series scale, with the exactsize selected being dependent on the particular type of formation to befractured, the available pressure and pumping rates, as well as otherfactors known to those skilled in the art.

Typical particulate agents employed in the wellbore fluids used asgravel packing fluids include, but are not limited to, quartz sandgrains, glass beads, synthetic resins, resin coated sand, walnut shells,and nylon pellets. The gravel pack particulate agents are generally usedin concentrations of about 1 to about 20 pounds per gallon of thewellbore fluid. The size of the particulate agent employed depends onthe type of subterranean formation, the average size of formationparticles, and other parameters known to those skilled in the art.Generally, particulate agents of about 8 to about 70 mesh on the U.S.Sieve Series scale are used.

Illustrative viscosifiers, organophilic clays, and fluid loss controlagents optionally used in wellbore fluids and their concentrations arethe same as discussed above in connection with drilling fluids.

The wellbore fluids are prepared by combining the synthetic fluid withany additional additive (e.g., hydraulic fracturing proppants; gravelpack particulate agents, viscosifiers, fluid loss control agents, andorganophilic clays). The synthetic fluid typically comprises at leastabout 50 weight percent of the wellbore fluid, the weight percent beingbased on the weight of all ingredients present in the wellbore fluid.Accordingly, wellbore fluids containing at least about 60, 70, 80, oreven 90 weight percent synthetic fluid are not uncommon. (In fact, insome cases, the synthetic fluid constitutes the entire wellbore fluid.)In terms of the liquid fraction of the wellbore fluid, the syntheticfluid generally comprises from about 50 to 100 weight percent of theliquids employed in wellbore fluids. For example, the synthetic fluidcan comprise at least about 60, 70, 80, or 90 weight percent of theliquid portion of the wellbore fluid.

The specific techniques used when employing the wellbore fluid aredetermined by its intended use and are analogous to methodologiesemployed when using prior art wellbore fluids for correspondingcompletion or work-over operations. For example, when the wellbore fluidis employed as a gravel packing fluid, it is typically injected into theformation in accordance with the procedure discussed in U.S. Pat. No.4,552,215, this patent being incorporated herein in its entirety byreference.

When employed as a fracturing fluid, the wellbore fluid of the presentinvention is usually injected into the formation using proceduresanalogous to those disclosed in U.S. Pat. No. 4,488,975; U.S. Pat. No.4,553,601; Howard et al., Hydraulic Fracturing, Society of PetroleumEngineers of the American Institute of Mining, Metallurgical, andPetroleum Engineers, Inc., New York, N.Y. (1970); and Allen et al.,Production Operations, Well completions, Workover, and Stimulation, 3rdEdition, Oil & Gas Consultants International, Inc., Tulsa, Okla. (1989)(Allen), volume 2, chapter 8; these patents and publications beingincorporated herein in their entirety by reference.

When employed in a perforating operation, the wellbore fluid of thepresent invention is used according to the methodologies disclosed involume 1, chapter 7 of Allen, referenced above.

Techniques for using packer fluids and well killing fluids, such asthose discussed in volume 1, chapter 8 of Allen, are also applicable tothe wellbore fluid of the present invention.

In addition, because the synthetic fluids of the present invention arelubricious, they can constitute up to about 10, and preferably fromabout 2 to about 5, weight percent of a water-based drilling fluid. Infact, any moving parts can be lubricated with these synthetic fluids.

Furthermore, while the synthetic fluid is generally manufactured by theFischer-Tropsch process and various modifications thereof, fluidsmeeting the specifications set forth above in Tables I-V can also beobtained by further processing various petroleum refinery products(e.g., subjecting a petroleum product to further distillation,hydroisomerization, and/or hydrocracking procedures).

In view of the foregoing numerous other embodiments, the spirit andscope of the appended claims should not necessarily be limited to thedescription of the preferred versions contained herein.

What is claimed is:
 1. A method for drilling a borehole in a subterranean formation, the method comprising the steps of: (A) rotating a drill bit at the bottom of the borehole; and (B) introducing a drilling fluid into the borehole to pick up drill cuttings and to carry at least a portion of the drill cuttings out of the borehole, where the drilling fluid comprises: (I) at least one additive selected from the group consisting of emulsifiers, wetting agents, viscosifiers, weighting agents, and fluid loss control agents; and (II) a base fluid comprising a mixture of paraffins prepared, at least in part, by a Fischer-Tropsch process, the mixture having a pour point less than about 10° C. (50° F.).
 2. The method of claim 1 where the Fischer-Tropsch synthesis includes the step of reacting carbon monoxide and hydrogen over a catalyst to produce highly linear products.
 3. The method of claim 1 where the Fischer-Tropsch synthesis includes the steps of (a) reacting carbon monoxide and hydrogen over a catalyst to produce highly linear products, a portion of which are olefins, and (b) hydrogenating at least some of the olefins.
 4. The method of claim 1 where the Fischer-Tropsch synthesis includes the steps of (a) reacting carbon monoxide and hydrogen over a catalyst to produce highly linear products, a portion of which are olefins, (b) hydrogenating at least some of the olefins, and (c) hydroisomerizing at least some of the products of steps (a) and/or (b).
 5. The method of claim 1 where the Fischer-Tropsch synthesis includes the steps of (a) reacting carbon monoxide and hydrogen over a catalyst to produce highly linear products, a portion of which are olefins, (b) hydrogenating at least some of the olefins to produce n-paraffin products, (c) hydroisomerizing at least some of the products of steps (a) and/or (b), and (d) hyrocracking at least some of the products of steps (a) and/or (b).
 6. The method of claim 1 where the drilling fluid is non-toxic.
 7. The method of claim 1 where the drilling fluid yields a 96 hour LC₅₀ Mysid shrimp bioassay test result greater than 100,000.
 8. The method of claim 1 where the base fluid comprises about 40 to about 100 volume percent paraffins and up to about 60 volume percent water and the paraffins consist essentially of the Fischer-Tropsch synthesis reaction product.
 9. The method of claim 1 where the base fluid comprises about 40 to about 100 volume percent paraffins, up to about 60 volume percent water, the paraffins consist essentially of the Fischer-Tropsch synthesis reaction product, and the drilling fluid yields a 96 hour LC₅₀ Mysid shrimp bioassay test result greater than 100,000.
 10. A method for drilling a borehole in a subterranean formation, the method comprising the steps of: (A) rotating a drill bit at the bottom of the borehole; and (B) introducing a drilling fluid into the borehole to pick up drill cuttings and to carry at least a portion of the drill cuttings out of the borehole, where the drilling fluid comprises: (I) at least one additive selected from the group consisting of emulsifiers, wetting agents, viscosifiers, weighting agents, and fluid loss control agents; and (II) a base fluid comprising a mixture of paraffins prepared, at least in part, by a Fischer-Tropsch process, the mixture having a viscosity at 40° C. (104° F.) of 1 to about 10 cst.
 11. A method for drilling a borehole in a subterranean formation, the method comprising the steps of: (A) rotating a drill bit at the bottom of the borehole; and (B) introducing a drilling fluid into the borehole to pick up drill cuttings and to carry at least a portion of the drill cuttings out of the borehole, where the drilling fluid comprises: (I) at least one additive selected from the group consisting of emulsifiers, wetting agents, viscosifiers, weighting agents, and fluid loss control agents; and (II) a base fluid comprising a mixture of paraffins prepared, at least in part, by a Fischer-Tropsch process, the mixture being composed of less than 1 weight percent of hydrocarbons containing more than 25 carbon atoms.
 12. A method for drilling a borehole in a subterranean formation, the method comprising the steps of: (A) rotating a drill bit at the bottom of the borehole; and (B) introducing a drilling fluid into the borehole to pick up drill cuttings and to carry at least a portion of the drill cuttings out of the borehole, where the drilling fluid comprises: (I) at least one additive selected from the group consisting of emulsifiers, wetting agents, viscosifiers, weighting agents, and fluid loss control agents; and (II) a base fluid comprising a mixture of paraffins prepared, at least in part, by a Fischer-Tropsch process, the mixture comprising 40 to 85 volume percent of the drilling fluid.
 13. A method for drilling a borehole in a subterranean formation, the method comprising the steps of: (A) rotating a drill bit at the bottom of the borehole; and (B) introducing a drilling fluid into the borehole to pick up drill cuttings and to carry at least a portion of the drill cuttings out of the borehole, where the drilling fluid comprises: (I) at least one additive selected from the group consisting of emulsifiers, wetting agents, viscosifiers, weighting agents, and fluid loss control agents; and (II) a base fluid comprising a mixture of paraffins prepared by hydrogenating a Fischer-Tropsch synthesis reaction product process, the mixture having a pour point less than about 10° C. (50° F.).
 14. A method for drilling a borehole in a subterranean formation, the method comprising the steps of: (A) rotating a drill bit at the bottom of the borehole; and (B) introducing a drilling fluid into the borehole to pick up drill cuttings and to carry at least a portion of the drill cuttings out of the borehole, where the drilling fluid comprises: (I) at least one additive selected from the group consisting of emulsifiers, wetting agents, viscosifiers, weighting agents, and fluid loss control agents; and (II) a base fluid comprising a mixture of paraffins prepared, at least in part, by a Fischer-Tropsch process, the mixture having at least two of the following three properties: (a) a pour point less than about 10° C. (50° F.); (b) a viscosity at 40° C. (104° F.) of 1 to about 10 cst; and (c) a concentration of less than 1 weight percent of hydrocarbons containing more than 25 carbon atoms.
 15. The method of claim 14 where the mixture has a pour point less than about 10° C. (50° F.) and a viscosity at 40° C. (104° F.) of 1 to about 10 cst.
 16. The method of claim 14 where the mixture has a pour point less than about 10° C. (50° F.) and a concentration of less than 1 weight percent of hydrocarbons containing more than 25 carbon atoms.
 17. The method of claim 14 where the mixture has a viscosity at 40° C. (104° F.) of 1 to about 10 cst and a concentration of less than 1 weight percent of hydrocarbons containing more than 25 carbon atoms.
 18. The method of claim 14 where the mixture has a pour point less than about 10° C. (50° F.), a viscosity at 40° C. (104° F.) of 1 to about 10 cst, and a concentration of less than 1 weight percent of hydrocarbons containing more than 25 carbon atoms.
 19. The method of claim 14 where the mixture comprises 40 to 85 volume percent of the wellbore fluid. 